WO2015132557A1 - Appareil et procédé de traitement de gaz naturel - Google Patents

Appareil et procédé de traitement de gaz naturel Download PDF

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WO2015132557A1
WO2015132557A1 PCT/GB2015/050449 GB2015050449W WO2015132557A1 WO 2015132557 A1 WO2015132557 A1 WO 2015132557A1 GB 2015050449 W GB2015050449 W GB 2015050449W WO 2015132557 A1 WO2015132557 A1 WO 2015132557A1
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Prior art keywords
hydrogenolysis
natural gas
hydrogen
vessel
process according
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PCT/GB2015/050449
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English (en)
Inventor
Peter Edward James Abbott
Peter Carnell
Martin Fowles
Matthew HUMPHRYS
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Johnson Matthey Public Limited Company
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Publication of WO2015132557A1 publication Critical patent/WO2015132557A1/fr

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    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01J—CHEMICAL OR PHYSICAL PROCESSES, e.g. CATALYSIS OR COLLOID CHEMISTRY; THEIR RELEVANT APPARATUS
    • B01J23/00—Catalysts comprising metals or metal oxides or hydroxides, not provided for in group B01J21/00
    • B01J23/38—Catalysts comprising metals or metal oxides or hydroxides, not provided for in group B01J21/00 of noble metals
    • B01J23/40—Catalysts comprising metals or metal oxides or hydroxides, not provided for in group B01J21/00 of noble metals of the platinum group metals
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
    • C10L3/00—Gaseous fuels; Natural gas; Synthetic natural gas obtained by processes not covered by subclass C10G, C10K; Liquefied petroleum gas
    • C10L3/06—Natural gas; Synthetic natural gas obtained by processes not covered by C10G, C10K3/02 or C10K3/04
    • C10L3/10—Working-up natural gas or synthetic natural gas
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01J—CHEMICAL OR PHYSICAL PROCESSES, e.g. CATALYSIS OR COLLOID CHEMISTRY; THEIR RELEVANT APPARATUS
    • B01J23/00—Catalysts comprising metals or metal oxides or hydroxides, not provided for in group B01J21/00
    • B01J23/38—Catalysts comprising metals or metal oxides or hydroxides, not provided for in group B01J21/00 of noble metals
    • B01J23/40—Catalysts comprising metals or metal oxides or hydroxides, not provided for in group B01J21/00 of noble metals of the platinum group metals
    • B01J23/46—Ruthenium, rhodium, osmium or iridium
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01J—CHEMICAL OR PHYSICAL PROCESSES, e.g. CATALYSIS OR COLLOID CHEMISTRY; THEIR RELEVANT APPARATUS
    • B01J23/00—Catalysts comprising metals or metal oxides or hydroxides, not provided for in group B01J21/00
    • B01J23/38—Catalysts comprising metals or metal oxides or hydroxides, not provided for in group B01J21/00 of noble metals
    • B01J23/40—Catalysts comprising metals or metal oxides or hydroxides, not provided for in group B01J21/00 of noble metals of the platinum group metals
    • B01J23/46—Ruthenium, rhodium, osmium or iridium
    • B01J23/462—Ruthenium
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01J—CHEMICAL OR PHYSICAL PROCESSES, e.g. CATALYSIS OR COLLOID CHEMISTRY; THEIR RELEVANT APPARATUS
    • B01J23/00—Catalysts comprising metals or metal oxides or hydroxides, not provided for in group B01J21/00
    • B01J23/38—Catalysts comprising metals or metal oxides or hydroxides, not provided for in group B01J21/00 of noble metals
    • B01J23/40—Catalysts comprising metals or metal oxides or hydroxides, not provided for in group B01J21/00 of noble metals of the platinum group metals
    • B01J23/46—Ruthenium, rhodium, osmium or iridium
    • B01J23/464—Rhodium
    • C—CHEMISTRY; METALLURGY
    • C07—ORGANIC CHEMISTRY
    • C07C—ACYCLIC OR CARBOCYCLIC COMPOUNDS
    • C07C4/00—Preparation of hydrocarbons from hydrocarbons containing a larger number of carbon atoms
    • C07C4/02—Preparation of hydrocarbons from hydrocarbons containing a larger number of carbon atoms by cracking a single hydrocarbon or a mixture of individually defined hydrocarbons or a normally gaseous hydrocarbon fraction
    • C07C4/06—Catalytic processes
    • C—CHEMISTRY; METALLURGY
    • C07—ORGANIC CHEMISTRY
    • C07C—ACYCLIC OR CARBOCYCLIC COMPOUNDS
    • C07C9/00—Aliphatic saturated hydrocarbons
    • C07C9/02—Aliphatic saturated hydrocarbons with one to four carbon atoms
    • C07C9/04—Methane
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
    • C10L3/00—Gaseous fuels; Natural gas; Synthetic natural gas obtained by processes not covered by subclass C10G, C10K; Liquefied petroleum gas
    • C10L3/06—Natural gas; Synthetic natural gas obtained by processes not covered by C10G, C10K3/02 or C10K3/04
    • C10L3/10—Working-up natural gas or synthetic natural gas
    • C10L3/101—Removal of contaminants
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
    • C10L3/00—Gaseous fuels; Natural gas; Synthetic natural gas obtained by processes not covered by subclass C10G, C10K; Liquefied petroleum gas
    • C10L3/06—Natural gas; Synthetic natural gas obtained by processes not covered by C10G, C10K3/02 or C10K3/04
    • C10L3/10—Working-up natural gas or synthetic natural gas
    • C10L3/101—Removal of contaminants
    • C10L3/102—Removal of contaminants of acid contaminants
    • C10L3/103—Sulfur containing contaminants
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
    • C10L2230/00—Function and purpose of a components of a fuel or the composition as a whole
    • C10L2230/04—Catalyst added to fuel stream to improve a reaction
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
    • C10L2290/00—Fuel preparation or upgrading, processes or apparatus therefore, comprising specific process steps or apparatus units
    • C10L2290/06—Heat exchange, direct or indirect
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
    • C10L2290/00—Fuel preparation or upgrading, processes or apparatus therefore, comprising specific process steps or apparatus units
    • C10L2290/10—Recycling of a stream within the process or apparatus to reuse elsewhere therein
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
    • C10L2290/00—Fuel preparation or upgrading, processes or apparatus therefore, comprising specific process steps or apparatus units
    • C10L2290/24—Mixing, stirring of fuel components
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
    • C10L2290/00—Fuel preparation or upgrading, processes or apparatus therefore, comprising specific process steps or apparatus units
    • C10L2290/38—Applying an electric field or inclusion of electrodes in the apparatus

Definitions

  • This invention relates to a process and apparatus for treating natural gas to remove higher hydrocarbons present therein.
  • renewable electricity e.g. from solar or wind source
  • This is leading to situations where renewable power generation is in excess of controllable demand.
  • This can lead to the curtailment of the renewable power generation, which results in under-utilisation of the equipment installed to generate power from the renewable source.
  • ways of storing this renewable energy or converting it to a useful product are being investigated.
  • One way is to use the power to generate renewable-hydrogen by electrolysis, but there still needs to be a method to store and/or realise the energy content of the renewable-hydrogen once produced.
  • WO201 1 /083297 discloses a process for treating a natural gas stream containing methane and one or more higher hydrocarbons comprising the steps of: (i) mixing at least a portion of the natural gas stream with steam, (ii) passing the mixture adiabatically over a supported precious metal reforming catalyst at an inlet temperature in the range 150-300°C to generate a reformed gas mixture comprising methane, steam, carbon dioxide, carbon monoxide and hydrogen, (iii) cooling the reformed gas mixture to below the dew point to condense water and removing the condensate to provide a de-watered reformed gas mixture, and (iv) passing the de-watered reformed gas mixture through an acid gas recovery unit to remove carbon dioxide and at least a portion of the hydrogen and carbon monoxide, thereby generating a methane stream. While effective in producing a methane stream, the need for steam generation, condensate removal and C02-removal may be disadvantageous in some cases.
  • US2009158660 discloses a method for adjusting the composition of natural gas containing high levels of C2+ (6-30% ethane + propane) prior to entry into a pipeline.
  • the method makes use of the available hydrogen in the feed to convert the higher hydrocarbons (especially ethane), as well as the carbon oxides, into methane, through catalytic hydrogenolysis and other reactions.
  • the preferred catalytic materials were transition metals (particularly nickel, cobalt, osmium, iridium, rhodium, ruthenium and rhenium) supported on metal oxide supports.
  • the invention provides a process for treating a natural gas stream containing methane and one or more higher hydrocarbons comprising the steps of:
  • the invention further provides apparatus for treating a natural gas stream containing methane and one or more higher hydrocarbons comprising:
  • a hydrogenolysis vessel comprising the mixer or operatively connected to the mixer, said hydrogenolysis vessel containing a supported precious metal hydrogenolysis catalyst, arranged in the vessel such that a stream of the mixed natural gas and hydrogen is passed over the catalyst to generate a treated gas mixture comprising methane and a reduced amount of the one or more higher hydrocarbons.
  • the invention provides a way of using surplus renewable energy and may provide a greater volume of saleable gas. The invention may also improve the quality of the natural gas by reducing the amount of higher hydrocarbons.
  • hydrolysis we mean the reaction of hydrogen with higher hydrocarbons to form methane. This is illustrated for ethane as follows;
  • the hydrogenolysis vessel consumes hydrogen and so may be termed a "de-hydrogenator".
  • “higher hydrocarbons” we include one or more of ethane, propane, butanes and any C5+ paraffins, cycloalkakanes such as cyclohexane, and aromatic hydrocarbons such as benzene.
  • the process is particularly effective where the higher hydrocarbons are selected from the group consisting of ethane, propane, butane and C5+ paraffins.
  • the process may be operated on-shore or offshore as long as there is a source of electrolytic hydrogen and a source of natural gas containing one or more higher hydrocarbons.
  • the natural gas stream maybe any natural gas stream, including conventional natural gas or an associated gas, recovered from on-shore or off-shore reservoirs, or another gas mixture comprising methane and one or more higher hydrocarbons.
  • the natural gas stream may be natural gas itself, it may alternatively be a substitute natural gas mixture comprising a mixture of methane or natural gas and one or more higher hydrocarbons.
  • the natural gas stream may alternatively be a shale gas, tight sand gas, coal-bed methane gas, or a biogas that contain one or more higher hydrocarbons.
  • the natural gas may comprise carbon dioxide and/or nitrogen.
  • the amount of methane in the natural gas stream is in the range 70 to 99% by volume, preferably 75 to 95% by volume more preferably 80 to 90% by volume.
  • One or more higher hydrocarbons may be present in the natural gas.
  • the ethane content may be in the range 1 to 15% by volume; the propanes content may be in the range 0.5 to 5% by volume and the butanes content may be 0.1 to 1 % by volume.
  • Carbon dioxide may be present in the natural gas at levels in the range 0.1 to 5% by volume.
  • the natural gas contains mercury it may be desirable to include a step of purifying the natural gas to remove mercury. Removing mercury protects process operators and equipment.
  • the process may further comprise passing the natural gas over a mercury sorbent disposed in a purification vessel upstream of the hydrogenolysis vessel.
  • Suitable mercury sorbents include transition metal sulphides, particularly copper sulphide, mixed with various support materials in the form of agglomerates. Such materials are commercially available from Johnson Matthey PLC, for example as PURASPEC JM TM 1 163.
  • a sorbent comprising a non-sulphided transition metal compound e.g.
  • copper hydroxycarbonate may be provided in a suitable form to the purification vessel and sulphided in-situ by sulphur compounds present in the natural gas, thereby resulting in co-removal of sulphur and mercury.
  • the mercury removal step is preferably operated below 150°C, more preferably below 100°C and at pressures up to about 200 bar abs, e.g. in the range 10-100 bar abs. Accordingly a mercury removal stage may be included before or after any stage of heating the natural gas stream.
  • the process further comprises a step purifying the natural gas stream to remove sulphur compounds upstream of the hydrogenolysis step in order to protect the hydrogenolysis catalyst from the poisoning effect of sulphur.
  • the process may further comprise passing the natural gas or the mixture of natural gas and hydrogen over one or more desulphurisation materials disposed in a purification vessel upstream of the hydrogenolysis vessel.
  • the desulphurisation of the natural gas stream is preferably carried out upstream of the hydrogenolysis vessel and downstream of the means for adding hydrogen. This is so the added hydrogen may be used in part to hydrodesulphurise any organo-sulphur compounds present in the natural gas.
  • the sulphur compounds may include one or more of hydrogen sulphide (H 2 S), carbonyl sulphide (COS), mercaptans, sulphides and thiophenes.
  • H 2 S may simply be absorbed using one or more beds of sulphur absorbent such as a commercially available ZnO or a metal-promoted, e.g. Cu- and/or Ni-promoted ZnO/alumina compositions, at temperatures in the range 50-300°C.
  • sulphur compounds other than hydrogen sulphide are present in high concentrations it may be desirable to include a first step of hydrodesulphurisation followed by a step of hydrogen sulphide absorption.
  • the desulphurisation materials comprise a bed of hydrodesulphurisation catalyst located upstream of a bed of hydrogen sulphide absorbent.
  • the mixture of natural gas and hydrogen are passed over a Ni- and/or Co-based catalyst that converts the organo-sulphur compounds to hydrogen sulphide.
  • Typical catalysts are alumina-supported Ni/Mo, Co/Mo, Ni/W and Co/W catalysts. Such catalysts are available commercially.
  • the hydrogen sulphide thus generated, in addition to any hydrogen sulphide naturally present in the natural gas may then be absorbed a suitable hydrogen sulphide absorbent such as a ZnO-material. Again such absorbent materials are available commercially.
  • the hydrodesulphurisation catalyst may also be effective for hydrogenating olefins and converting amines present in the natural gas to ammonia.
  • hydrodesulphurisation catalyst and hydrogen sulphide absorbent may be in the same or different vessels.
  • the combined hydrodesulphurisation and H 2 S absorption is preferably operated above 150°C, more preferably above 200°C and at pressures in the range 10-100 bar abs, preferably in the range 10-50 bar abs.
  • the natural gas stream is desirably preheated prior to purification using conventional means such as a fired heater or by exchanging heat with the treated gas mixture.
  • the hydrogen stream is generated by the electrolysis of water.
  • Apparatus and processes for the electrolysis of water are known and may be used in the present invention. Such processes include alkaline electrolysers and PEM electrolysers. It is a particular advantage, if the apparatus is designed to generate hydrogen at sufficient pressure, so that no further compression is required to inject it into the natural gas stream.
  • Electricity for the electrolysis may be recovered from a suitable electricity source. It is particularly preferred that the electricity used for the electrolysis is generated from a renewable source. Any renewable source may be used, for example electricity for the electrolysis may be generated by wind- turbines, by hydro-electric means such as wave- or tidal-power generators, by solar power generators, or may be derived from a geothermal source. Wind-turbine generated electricity or solar power generated electricity are particularly convenient.
  • the electrolyser which is used for generating the hydrogen, may be connected directly to the renewable power source, in a scenario, which is commonly referred to as 'Off Grid'.
  • 'Off Grid' a scenario, which is commonly referred to as 'Off Grid'.
  • 'Grid Connected' a scenario, which is called 'Grid Connected'.
  • the natural gas stream is mixed with the hydrogen. This may be by direct injection of hydrogen using a separate mixing apparatus or the mixing step may be performed at the inlet of the hydrogenolysis vessel.
  • the amount of hydrogen necessary for the hydrogenolysis reactions will depend upon the higher hydrocarbon content of the natural gas and upon which higher hydrocarbons are present. Typically the amount of hydrogen in the mixture with the natural gas will be in the range 6 to 24% by volume, for example, 8 to16% by volume.
  • the gas mixture fed to the hydrogenolysis catalyst consists of a natural gas stream containing methane and one or more higher hydrocarbons, and hydrogen.
  • the process may be configured to react away all the hydrogen, if the higher hydrocarbon content is high enough, in which case there will be residual higher hydrocarbon in the treated gas. Indeed, it may be desirable in some cases to have a portion of the higher hydrocarbon remaining in the treated gas stream in order to meet product gas specifications.
  • the process can be used to augment the hydrogen carrying capacity of the gas if the hydrogen concentration exceeds that for consumption of the higher hydrocarbons, in which case the treated gas will comprise residual hydrogen. In both cases the problems of the prior art processes are ameliorated.
  • the reverse water-gas shift reaction to generate carbon monoxide and water may also occur over the precious metal hydrogenolysis catalyst, although the amount of hydrogen consumed will typically be very low under the reaction conditions.
  • the reversible water-gas shift reaction may be depicted as follows: C0 2 + H 2 ⁇ -> CO + H 2 0
  • precious metal catalyst may also be selected, which is active for the methanation reaction of carbon dioxide with hydrogen, in which case a greater amount of hydrogen can be consumed to generate even more saleable methane.
  • the methanation reaction may be depicted as follows:
  • the temperature of the natural gas stream/hydrogen mixture may be controlled for example using a preheater, and is in the range 100-300°C, but is preferably 150-275°C, more preferably, 200-250°C at the inlet of the hydrogenolysis vessel. Higher inlet temperatures may be used, for example up to 500°C.
  • the process may be operated at pressures in the range 2-150 bar abs, preferably 10-150 bar abs, more preferably in the range 10-100 bar abs, and in particular 10-50 bar abs, which may be achieved by compression of the natural gas stream, where necessary. Compression of the hydrogen to the process pressure may be performed separately or the mixed gas may be compressed.
  • the mixture comprising the natural gas stream and hydrogen is passed to a hydrogenolysis vessel containing a supported precious metal reforming catalyst. Hydrogenolysis reactions take place over the precious metal catalyst to convert the higher hydrocarbons present to methane. If carbon dioxide is present, the reverse water-gas shift reaction and methanation reaction may also take place.
  • the hydrogenolysis catalyst is a supported precious metal catalyst.
  • Suitable catalysts comprise one or more of Pt, Pd, Ir, Rh or Ru, preferably Rh or Ru.
  • Especially preferred catalysts comprise Ru, on a catalyst support, optionally with one or more promoters.
  • Ru catalysts have a suitably low light-off temperature for the hydrogenolysis reactions.
  • Precious metal loading on the support may be in the range 0.1 -10.0% wt, but is preferably 0.5-5% by weight.
  • the catalyst support may be any conventional catalyst support such as alumina, magnesia, titania, zirconia or other oxide materials.
  • the hydrogenolysis catalyst may be in the form of shaped units such as spheres, trilobes, quadralobes, cylindrical pellets or rings or cylinders with one or more through-holes and/or one or more flutes or grooves running along the length of the unit. Such shaped units offer high geometric surface areas combined with low pressure drop.
  • the catalyst may be in the form of a monolith, i.e. a honeycomb, formed from a metal or ceramic substrate onto which a washcoat containing the precious metal has been coated.
  • Suitable catalysts may be prepared by conventional methods such as by impregnating the support with a soluble salt of precious metal or by preparing a washcoat containing a suitable precious metal compound and coating the support with the washcoat, followed by drying, calcination and, if desired, reduction of the catalyst metal to its active form. Reduction of the metal may if desired be performed in-situ, in which case the catalyst may be provided in oxidic form.
  • a simple, adiabatic fixed bed reactor can be used.
  • a simple, adiabatic gas-cooled reactor design may be utilised.
  • a cooled tube design e.g. steam raising
  • hydrogenolysis reactions is managed to prevent catalyst damage and unwanted side-reactions.
  • An alternative means to control the temperature for a high level of hydrogen addition is to use a recycle stream of cooled product gas to reduce the exotherm in the hydrogenolysis vessel.
  • circulation means may be provided to compress a portion of cooled product stream and recycle it to the inlet of the vessel.
  • the exit temperature from the hydrogenolysis vessel is preferably in the range 250-400°C.
  • the treated gas mixture may be used in downstream processes as it is, but it is preferably cooled and, if need be dried, if there is some water content.
  • the treated gas mixture may be passed through a heat exchanger to cool it to a temperature below about 75°C, e.g. 10-50°C.
  • the cooled treated gas mixture may be further treated, for example, it may be dried if desired using e.g. silica gel or molecular sieves, and/or compressed for pipeline distribution using conventional equipment, or it may be mixed with an untreated natural gas stream and processed to provide a fuel or feedstock for domestic or industrial use.
  • the reaction of hydrogen with gas in this way produces a larger quantity of gas with a lower calorific value.
  • it is desirable to reduce the calorific value or Wobbe index of a gas if it is too high for the specification of the gas distribution network downstream.
  • the consumption of hydrogen may be used to condition such a gas, so that it has a lower calorific value (CV) or Wobbe index (Wl).
  • CV calorific value
  • Wl Wobbe index
  • the present invention may then be used to bring the gas into the required specification range.
  • the maximum amount of hydrogen may be used while at the same time meeting the desired product gas specification.
  • the reverse water-gas shift and methanation reactions may be used to lower the carbon dioxide content of the natural gas to pipeline specifications.
  • the reverse water-gas shift and methanation reactions produce water as a by-product, which may need to be removed to meet dew-point specifications.
  • the present process is a rather simple, fixed bed reaction process using one or two heat exchangers, which is anticipated to be relatively inexpensive and therefore attractive to use.
  • FIG. 1 is a flow-sheet depicting a process according to a first embodiment
  • a renewable electricity source 10 such as a wind-turbine, hydroelectric-, wave- or tidal power generator or a solar power generator, preferably a wind turbine or a solar panel array
  • a renewable electricity source 10 provides electricity via line 12 to an electrolysis unit 14 fed with water via line 16.
  • the electrolysis unit 14 splits the water to generate oxygen, which is vented via line 18 and hydrogen.
  • the hydrogen is compressed and fed by line 20 into to a source of natural gas 22, which contains ethane, propane & butane in addition to methane.
  • the resulting mixture of natural gas and hydrogen is fed via line 24 to a heat exchanger 26 where it is heated.
  • the heated gas mixture passes via line 28 to a purification vessel 30 containing a fixed bed of a particulate Co/Mo hydrodesulphurisation catalyst over a fixed bed of a particulate ZnO hydrogen sulphide adsorbent.
  • the purification vessel removes trace amounts of organic sulphur compounds and hydrogen sulphide from the gas mixture. Mercury present in the mixture may also be removed concomitantly.
  • the gas mixture passes from the purification vessel 30 via line 32 at a temperature of about 220°C to the inlet of a hydrogenolysis vessel 34 (de-hydrogenator) containing a fixed bed of a particulate supported ruthenium hydrogenolysis catalyst.
  • the gas mixture passes adiabatically through the catalyst bed where the
  • hydrogenolysis reactions take place. Where carbon dioxide is present in the natural gas, methanation and reverse water-gas shift reactions may also take place. The reaction is exothermic and the gas is heated as it passes through the vessel 34. A treated gas mixture comprising methane and a reduced amount of higher hydrocarbons is recovered from the de- hydrogenator 34 via line 36. The treated gas is passed through heat exchanger 38 to cool it and form a cooled treated gas stream 40. The cooled treated gas stream 40 may be supplied as a fuel or used to adjust the calorific value of a natural gas stream.
  • This example illustrates a catalyst performing the hydrogenolysis reaction, where the added hydrogen is almost completely consumed.
  • the overall efficiency is about 58% which is competitive.
  • This example is based on the same quantity of renewable power and hydrogen production by electrolysis and the same inlet reactor temperature and pressure as Example 1 .
  • This example illustrates a catalyst performing the hydrogenolysis and reverse water gas shift reactions, where enough hydrogen is added to leave 0.5% hydrogen in the product gas.
  • the exit temperature from the reactor is 383°C.
  • the water content of the product gas is 0.24%
  • This example is based on the same quantity of renewable power and hydrogen production by electrolysis and the same inlet reactor temperature and pressure as Example 1 .
  • This example illustrates a catalyst performing just the C0 2 methanation and reverse water gas shift reactions (not according to this invention), where enough hydrogen is added to leave 0.5% hydrogen in the product gas.
  • the exit temperature from the reactor is 278°C.
  • This example is based on the same quantity of renewable power and hydrogen production by electrolysis and the same inlet reactor temperature and pressure as Example 1 .
  • This example illustrates a catalyst performing the hydrogenolysis, C0 2 methanation and reverse water gas shift reactions, where enough hydrogen is added to leave 0.5% hydrogen in the product gas.
  • the exit temperature from the reactor is 387°C.
  • the water content of the product gas is 0.4%

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  • Chemical & Material Sciences (AREA)
  • Organic Chemistry (AREA)
  • Engineering & Computer Science (AREA)
  • Oil, Petroleum & Natural Gas (AREA)
  • Chemical Kinetics & Catalysis (AREA)
  • General Chemical & Material Sciences (AREA)
  • Materials Engineering (AREA)
  • Organic Low-Molecular-Weight Compounds And Preparation Thereof (AREA)

Abstract

L'invention concerne un procédé permettant de traiter un flux de gaz naturel contenant du méthane et un ou plusieurs hydrocarbures supérieurs, qui comprend les étapes consistant : (i) à former un courant d'hydrogène par l'électrolyse d'eau, (ii) à mélanger au moins une partie du flux de gaz naturel avec le flux d'hydrogène, et (iii) à faire passer le mélange sur un catalyseur d'hydrogénolyse à base de métal précieux supporté disposé dans un récipient d'hydrogénolyse à une température d'entrée dans la plage de 100 à 300 °C pour générer un mélange gazeux traité comprenant du méthane et une quantité réduite du ou des hydrocarbures supérieurs.
PCT/GB2015/050449 2014-03-06 2015-02-17 Appareil et procédé de traitement de gaz naturel WO2015132557A1 (fr)

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GBGB1403937.4A GB201403937D0 (en) 2014-03-06 2014-03-06 Apparatus and process for treating natural gas

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CN105567363B (zh) * 2016-02-22 2017-12-26 中国石油集团工程设计有限责任公司 一种天然气脱蜡脱水脱烃装置及方法

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US20090158660A1 (en) * 2005-12-30 2009-06-25 Vanden Bussche Kurt M Process to Maximize Methane Content in Natural Gas Stream

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US3180902A (en) * 1961-08-10 1965-04-27 Engelhard Ind Inc Process for the hydrogenolysis of light hydrocarbons
US3421870A (en) * 1964-02-17 1969-01-14 Exxon Research Engineering Co Low-temperature catalytic hydrogen-olysis of hydrocarbons to methane
US4149998A (en) * 1976-04-05 1979-04-17 Exxon Research & Engineering Co. Supported metal interaction catalysts
ATE815T1 (de) * 1978-11-16 1982-04-15 Imperial Chemical Industries Plc Herstellung von methan durch hydrogenolysis von kohlenwasserstoffen; verfahren zur herstellung eines ruthenium-traegerkatalysators; ein ruthenium enthaltender katalysator.
FR2502142B1 (fr) * 1981-03-17 1983-12-02 Inst Francais Du Petrole

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US20090158660A1 (en) * 2005-12-30 2009-06-25 Vanden Bussche Kurt M Process to Maximize Methane Content in Natural Gas Stream

Non-Patent Citations (2)

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ANONYMOUS: "Power to gas - Wikipedia, the free encyclopedia", 22 January 2014 (2014-01-22), XP055182180, Retrieved from the Internet <URL:http://en.wikipedia.org/w/index.php?title=Power_to_gas&oldid=591900835> [retrieved on 20150410] *
TOBIAS TROST ET AL: "Renewable Methane: Analysis of COPotentials for Power-to-Gas in Germany ; Storing Renewable Energy in the Gas Distribution Network ; Erneuerbares Methan: Analyse der CO-Potenziale fà 1/4 r Power-to-Gas Anlagen in Deutschland ; Erneuerbare Energien im Gasnetz speichern", ZEITSCHRIFT Fà 1/4 R ENERGIEWIRTSCHAFT, VIEWEG VERLAG, WIESBADEN, vol. 36, no. 3, 17 April 2012 (2012-04-17), pages 173 - 190, XP035105382, ISSN: 1866-2765, DOI: 10.1007/S12398-012-0080-6 *

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GB201502642D0 (en) 2015-04-01

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